This application contains subject matter related to that disclosed in U.S. Pat. No. 6,016,702, entitled xe2x80x9cHigh Sensitivity Fiber Optic Pressure Sensors For Use In Harsh Environmentsxe2x80x9d; U.S. Pat. No. 6,354,147, entitled xe2x80x9cFluid Parameter Measurement in Pipes Using Acoustic Pressuresxe2x80x9d; U.S. patent application Ser. No. 09/740,760, entitled xe2x80x9cApparatus for Sensing Fluid in a Pipe,xe2x80x9d filed Nov. 29, 2000; U.S. patent application Ser. No. 09/346,607, entitled xe2x80x9cFlow Rate Measurement Using Unsteady Pressures,xe2x80x9d filed Jul. 2, 1999; U.S. patent application Ser. No. 09/997,221, entitled xe2x80x9cMethod And System For Determining The Speed Of Sound In A Fluid Within A Conduit,xe2x80x9d filed Nov. 28, 2001; U.S. Provisional Application Serial No. 60/250,997, entitled xe2x80x9cMethod And System For Determining The Speed Of Sound In A Fluid Within A Conduit,xe2x80x9d filed Dec. 4, 2000; and U.S. patent application Ser. No. 09/729,994, entitled xe2x80x9cMethod And Apparatus For Determining The Flow Velocity Within A Pipe,xe2x80x9d filed Dec. 4, 2000 all of which are incorporated herein by reference in their entirety.
This invention relates to multiphase flow measurement systems to monitor multiphase flow production. More particularly the present invention incorporates sound speed measurements to fundamentally improve the ability of multiphase flow measurement systems to determine phase flow rates of a fluid.
It is widely recognized that the ability to measure the individual flow rates of oil/water/gas within co-flowing mixtures of these substances has substantial economic value for the oil and gas industry. The industry has been actively developing multiphase flow meters for the past 20 years. During this development process, many techniques have been identified, evaluated, refined, and commercialized.
The numerous approaches to multiphase flow measurement of the prior art can typically be divided into two main categories of multiphase flow meters (MPFM""s). The first category seeks to develop instruments to measure the oil/water/gas flow rates based on localized measurement. This is a typical industry approach in which a variety of measurements are made on the oil/gas/water mixture to help determine the flow rates of the individual components. This approach has focused on developing novel and robust instruments designed to provide precise multiphase flow measurements, such as dual-intensity gamma densitomers, microwave meters, capacitance and conductance meters, etc. Typically MPFM""s are a collection of several essentially separate, but co-located measurement devices that provide a sufficient number of measurements to uniquely determine the flow rate at the meter location. Prior art multiphase flow meter manufacturers for monitoring hydrocarbon production include Roxar, Framo, and Fluenta, among others. These MPFM""s are typically restricted to operate above the well, either on the surface or subsea, for various reasons including reliability in the harsh environment and complications due to the presence of electrical power. Since the MPFM""s typically operate at pressures and temperatures determined by production conditions and operators are typically interested in oil and gas production at standard conditions, the flow rates measured at the meter location are translated to standard conditions through fluid properties data (Pressure, Temperature, and Volumetric properties (PVT)).
The second category of prior art MPFM""s provides multiphase flow rate information by utilizing measurements distributed over the production system in conjunction with a mathematical description, or model, of the production system. The mathematical model utilizes multiphase flow models to relate the parameters sought to estimates for the measured parameters. The flow rates are determined by adjusting the multiphase flow rates to minimize the error between the distributed measurements and those predicted by the mathematical model. The type, number, and location of the measurements that enter into this global minimization process to determine flow rates can vary greatly, with cost, reliability and accuracy all entering into determining the optimal system.
Several prior art MPFM""s have been developed utilizing distributed measurements to estimate production flow rates. Owing to the availability and relatively low cost and reliability of conventional pressure and temperature measurements, these systems have typically tended to focus on utilizing only distributed pressure and temperature measurements to determine flow rates. Unfortunately, the physics linking sparse pressure and temperature measurements to flow rates is rather indirect and relies on estimates of several, often ill-defined flow system properties such as viscosity and wall surface roughness. Thus, although it is theoretically possible to determine flow rates from a limited number of pressure and temperature measurements, it is generally difficult for such systems to match the accuracy of a dedicated multiphase flow measurement system as described above.
The distributed measurement approaches are fundamentally rooted in the relationship between flow rates and pressure and temperature. Specifically, pressure drop in flow within a pipe is due primarily to viscous losses which are related to flow rate, and hydrostatic head changes which are related to changes in density of fluid and hence composition. Axial temperature gradients are primarily governed by the radial heat transfer from the flow within the production tubing into the formation as the flow is produced and is related to the heat capacity of the fluid, heat transfer coefficients, and the flow rate. The pressure drop and temperature losses are used to predict flow rates. The fundamental problem with this approach is that the relationship between flow rate and either of these two parameters is highly uncertain and often must be calibrated or tuned on a case-by-case basis. For instance, it is known that it is extremely difficult to accurately predict pressure drop in multiphase flow.
It is also recognized that the accuracy of distributed measurement systems utilizing pressure and temperature measurements can be improved utilizing additional phase fraction measurements provided by prior art sensors such as density, dielectric, and sound wave measurements. These phase fraction measurements and/or volumetric flow rate measurements are performed by auxiliary sensors that constrain the global optimization for specific variables at specific locations. In addition to enhancing the overall accuracy and robustness, the auxiliary sensors reduce the need for in-situ tuning of the optimization procedure required to produce accurate results.
What is needed is a robust and accurate sensor apparatus for providing temperature, pressure and other flow related parameters to multiphase flow models. It is further necessary to provide a sensor that can survive in harsh downhole environments.
A multiphase flow measurement system is disclosed that incorporates fluid sound speed measurements into a multiphase flow model thereby fundamentally improving the system""s ability to determine phase flow rates of a fluid. The distributed system includes at least one flow meter disposed along the pipe, an additional sensor disposed along the pipe spatially removed from the flow meter, and a multiphase flow model that receives the flow related parameters from the flow meter and the additional sensor to calculate the phase flow rates. Depending on production needs and the reservoir dimensions, the distributed system may utilize a plurality of flow meters disposed at several locations along the pipe and may further include a plurality of additional sensors as well. The distributed system preferably uses fiber optic sensors with Bragg gratings. This enables the system to have a high tolerance for long term exposure to harsh temperature environments and also provides the advantage of multiplexing the flow meters and/or sensors together.
The flow meter provides parameters to the well bore model including pressure, temperature, velocity and sound speed of the fluid. To provide these parameters, the flow meter includes a pressure assembly and a flow assembly, which may be coupled together as a single assembly or separated into two subassemblies. The pressure assembly preferably contains a pressure sensor for measuring the pressure of the fluid and/or a temperature sensor for measuring the temperature of the fluid. The flow assembly preferably contains a fluid sound speed sensor for measuring the fluid sound speed and/or a velocity sensor for measuring the bulk velocity and volumetric flow rate of the fluid.
The additional sensor, along with the flow meter, provides the necessary parameters for the multiphase flow model to determine phase flow rates. The additional sensor is disposed along the pipe at a location, spatially removed, from the flow meter, preferably vertically removed, for e.g., downstream from the flow meter. The additional sensor may measure temperature, pressure or with a plurality of additional sensors measure both temperature and pressure. This measurement may be taken at the well head of the pipe, and preferably below the main choke valve.
The measurements from the additional sensor and the flow meter are received by an optimization procedure which seeks to adjust the parameters of a multiphase flow model of the systems such that the error between the measurements recorded by the sensors and those simulated by the model is minimized. The parameters for which the error is minimized yields the desired flow rates. A variety of multiphase flow models may be used to determine the phase flow rates. Models have incorporated pressure and temperature measurements previously; however, the present invention incorporates a fluid sound speed measurement into the model which significantly improves the ability of the model to determine phase flow rates.